Recovery of petroleum from viscous petroleum-containing formations including tar sands

ABSTRACT

A method for the in-situ recovery of low API gravity oils or bitumen from subterranean hydrocarbon-bearing formations wherein the recovery is optimized by the injection of a mixture of an oxygen-containing gas and steam until the recovery efficiency declines, followed by the injection of a mixture of light hydrocarbon and steam, under operating conditions that may utilize pressurization and drawdown cycles.

BACKGROUND OF THE INVENTION

This invention relates to an improved method for the in-situ recovery ofoil from subterranean hydrocarbon-bearing formations containing low APIgravity oil or bitumen. More particularly, the invention relates to anin-situ recovery method wherein improved recovery is realized byoptimizing the recovery by the injection of a mixture of anoxygen-containing gas and steam until the recovery efficiency declines,followed by the injection of a mixture of light hydrocarbon and steam,and employing pressurization and drawdown cycles.

The in-situ recovery of low API gravity oil from subterraneanhydrocarbon-bearing formations and bitumen from tar sands has generallybeen difficult. Although some improvement has been realized in thein-situ recovery of heavy oils, i.e., oils having an API gravity in therange of 10° to 25° API, little success has been realized in recoveringbitumen from tar sands by in-situ methods. Bitumen can be regarded as ahighly viscous oil having an API gravity in the range of about 5° to 10°API and a viscosity in the range of several million centipoise atformation temperature, and contained in an essentially unconsolidatedsand, generally referred to as a tar sand.

Extensive deposits of tar sands exist in the Athabasca region ofAlberta, Canada. While these deposits are estimated to contain aboutseven hundred billion barrels of bitumen, recovery therefrom, asindicated above, using conventional in-situ techniques has not beenaltogether successful. The reasons for the varying degrees of successrelate principally to the fact that the bitumen is extremely viscous atthe temperature of the formation, with consequent very low mobility. Inaddition, the tar sand formations have very low permeability, despitethe fact they are unconsolidated.

Since it is known that the viscosity of a viscous oil decreases markedlywith an increase in temperature, thereby improving its mobility, thermalrecovery techniques have been investigated for recovery of bitumen fromtar sands. These thermal recovery methods generally include steaminjection, hot water injection and in-situ combustion.

Typically, such thermal techniques employ an injection well and aproduction well traversing the oil-bearing or tar sand formation. In aconventional throughput steam operation, steam is introduced into theformation through an injection well. Upon entering the formation, theheat transferred by the hot fluid to the formation fluid lowers theviscosity of the oil, thereby improving its mobility, while the flow ofthe hot fluid serves to drive the oil toward the production well fromwhich it is produced.

Thermal techniques employing steam also utilize a single well technique,known as the "huff and puff" method. In this method, steam is injectedvia a well in quantities sufficient to heat the subterraneanhydrocarbon-bearing formation in the vicinity of the well. Following aperiod of soak, during which time the well is shut-in, the well isplaced on production. After production has declined, the huff and pufftechnique may again be employed on the same well to again stimulateproduction. In its application to a field pattern, the huff and pufftechnique may be phased so that numerous wells are on an injection cyclewhile others are on a production cycle, which cycles are then reversed.

In the conventional forward in-situ combustion, an oxygen-containinggas, such as air, is introduced into the formation via a well andcombustion of in-place crude is initiated adjacent the wellbore.Temperatures of the combustion generally are in the range of 600° to1200° F. Thereafter, the injection of the oxygen-containing gas iscontinued so as to maintain a combustion front by burning a portion ofthe in-place crude or a carbonized deposit resulting from the hightemperatures. The injected gas also drives the front through theformation toward a production well. As the combustion front advancesthrough the formation a swept zone consisting ideally of clean sand iscreated behind the front. Contiguous zones are built up ahead of thefront that may include a distillation and cracking zone and acondensation and vaporization zone. The formation of these zones isdependent principally upon the temperature gradients that are created inthe formation. As these zones are displaced through the formation, azone of high oil saturation or an oil bank is established ahead of them,which zone or bank is also displaced toward the production well fromwhich production occurs.

Among the improvements relating to in-situ combustion described in priorart is the injection of water either simultaneously or intermittentlywith the oxygen-containing gas to scavenge the residual heat, therebyincreasing the recovery of oil. Prior art also discloses regulation ofthe amount of the water injected with the air to improve conformance orsweep efficiency.

Experience has generally shown that in the application of theseconventional thermal techniques to the recovery of low API gravity oilsand particularly to bitumen recovery from tar sands, conventionalthermal techniques have their shortcomings. For example, one difficultyhas been that, as the build-up of the oil bank occurs ahead of thethermal front and is displaced through the formation, the bank cools andhence the oil again becomes immobile. The result is that plugging of theformation occurs, thereby making the injection of either theoxygen-containing gas in the case of in-situ combustion, or steam in thecase of steam, no longer possible.

An improved thermal method of recovery for low API gravity oil orbitumen from tar sands has been disclosed in U.S. Pat. No. 4,006,778,which utilizes a controlled low-temperature oxidation. According to itsteaching, a mixture of an oxygen-containing gas and steam is injectedinto the formation to generate, and thereafter control, an in-situlow-temperature oxidation. The mixture is injected at a temperaturecorresponding to the temperature of saturated steam at the pressure ofthe formation. By this method, the temperature is established and iscontrolled in the formation at a temperature much lower, i.e., generallyin the range of 250° to 500° F., than that of the conventional in-situcombustion process. One of the advantages of the method is theminimization of coking in the formation, which in the conventionalin-situ combustion may be excessive and lead to blockage of theformation.

Prior art also teaches the recovery of oil by use of solvents,especially hydrocarbon solvents, either at ambient or elevatedtemperature. One method is described in U.S. Pat. No. 3,608,638 whichemploys the injection of a hot hydrocarbon solvent such as toluene orkerosene. The solvent functions principally by dissolving the oil,thereby decreasing viscosity and improving mobility of the fluid. It isalso well-known to employ a mixture of hydrocarbon solvent and steam forthe recovery of bitumen from tar sand. It is believed that recovery isenhanced by the use of the steam and hydrocarbon mixture because notonly is the viscosity of the tar reduced, but also displacement throughthe sand occurs more rapidly than is possible by the injection of eithersteam alone or a hydrocarbon solvent. Such a method is described in U.S.Pat. No. 2,862,558 in which a mixture of steam and a normally liquidhydrocarbon is injected into a tar sand formation at a temperature ofabout 225° to 500° F. and at a pressure of at least 20 psig. Morerecently, patent literature has described the use of mixtures ofdepentanized naphtha and steam for recovery of bitumen from tar sandsuch as described in U.S. Pat. No. 3,945,435 and U.S. Pat. No.3,946,810. These patents teach that the solvent, having a high aromaticcontent, is produced from the recovered hydrocarbon and reinjected intothe formation with steam at a temperature in the range of 200° to 650°F.

We have now found that, by utilizing a two-step sequence employing theinjection of a mixture of an oxygen-containing gas and steam followed bythe injection of a mixture of a light hydrocarbon and steam, togetherwith the employment of pressurization and drawdown cycles, enhancedrecovery is realized that is higher than that obtained using either themixture of the oxygen-containing gas and steam or the mixture of thelight hydrocarbon and steam alone. Switchover from step (1) to step (2)is made after the recovery efficiency, which is optimized during thefirst step, begins to show a decline.

Accordingly, it is an object of the present invention to provide anoptimized in-situ recovery method for low gravity crudes and bitumenthat takes advantage of the beneficial aspects of the use of a mixtureof an oxygen-containing gas and steam and a mixture of a lighthydrocarbon and steam.

SUMMARY OF THE INVENTION

This invention relates to an improved in-situ method for recovering lowAPI gravity oils and more particularly to the production of bitumen fromtar sands by the sequential injection of a mixture of anoxygen-containing gas and steam, followed by the injection of a mixtureof a light hydrocarbon and steam. The injection of the mixture of anoxygen-containing gas and steam which optimizes the recovery efficiencyis continued until the recovery efficiency shows a decline. Thereafter,a mixture of a light hydrocarbon and steam is injected. The process mayalso utilize pressurization and drawdown cycles during each of theinjection phases.

A BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 compares the bitumen recovery (%) versus steam injected (porevolume) among tests employing the injection of mixtures of air and steamand mixtures of light hydrocarbon and steam.

FIG. 2 illustrates the recovery efficiency (pore volume bitumenproduced/pore volume steam injected) versus steam injected (pore volume)among tests employing the injection of mixtures of air and steam andmixtures of light hydrocarbon and steam.

FIG. 3 gives the bitumen recovery (%) versus steam injected (porevolume) for the recovery scheme utilizing the sequential injection of amixture of air and steam followed by the injection of a mixture of lighthydrocarbon and steam.

DESCRIPTION OF THE PREFERRED EMBODIMENT

In its broadest aspect this invention relates to an optimized method ofin-situ recovery for low API gravity oils or bitumen from tar sands byexploiting the benefits of the injection of a mixture of anoxygen-containing gas and steam and the injection of a mixture of alight hydrocarbon and steam. More particularly, the method is applied toa tar sand formation that is traversed by at least one injection welland one production well and between which there is a communication pathor zone of fluid transmissibility.

By the method of the instant invention, a mixture of anoxygen-containing gas and steam is injected into the formation and alow-temperature oxidation is established and controlled therein at atemperature much lower than the temperature of the conventional in-situcombustion process. Injection of the mixture is continued until themaximum recovery efficiency that has been attained begins to decline. Byrecovery efficiency is meant the ratio of the bitumen recovered to thesteam injected (in compatible units, e.g., pore volumes). After themaximum recovery efficiency begins to decline, the injection of themixture of the oxygen-containing gas and steam is terminated and theinjection of a mixture of a light hydrocarbon and steam is undertakenwhereby the optimization of recovery of bitumen is continued. In theoperation, pressurization and drawdown cycles may be employed.

In the first step of the invention the injection of a mixture of anoxygen-containing gas and steam is undertaken at a temperaturecorresponding to the temperature of saturated steam at the pressure ofthe formation. A low-temperature oxidation is effected at thetemperature of the saturated steam such as is described in U.S. Pat. No.4,006,778. It is desirable that the injection be accomplished at themaximum flow rate possible consistent with the pressure limitations ofthe formation. The preferred temperatures of the injected steam are inthe range of 250° to 500° F., corresponding to the temperature of thesaturated steam at the pressure of the formation. The quality of thesteam may be in the range of 60% up to about 100%, with the higherquality preferred, although comparable results have been obtained atlower qualities. Quality of steam is defined as the weight percent ofdry steam contained in one pound of wet steam.

The oxygen-containing gas may be air, or a mixture of oxygen andnon-condensible gases as nitrogen, carbon dioxide or flue gas, or it maybe substantially pure oxygen. By the term "oxygen-containing gas" ismeant that the gas mixture contains free oxygen as one component. Theratio of the free oxygen in the oxygen-containing gas to the steaminjected is generally in the range of about 30 SCF/bbl steam to 130SCF/bbl steam. In the situation where air is used, the ratio of the airto the steam in the mixture is in the range of about 150 SCF/bbl toabout 650 SCF/bbl. A preferred range is 170 to 250 SCF air/bbl steam.

Prior to the first step it may be necessary to condition the formationto develop adequate transmissibility in the formation or to stimulatethe wells. This may be accomplished by fracturing procedures well-knownin the art, and/or by the injection of steam into the wells.

After the injection of the mixture of the oxygen-containing gas andsteam has been initiated, and production of fluids (i.e., bitumen) hasoccurred at the production well, the recovery efficiency is monitored,which recovery efficiency has been heretofore defined as the porevolumes of bitumen recovered to the pore volumes of steam injected. Theinjection is continued until the recovery efficiency has reached amaximum and begins to decline.

Thereafter, the injection of the mixture of the oxygen-containing gasand steam is terminated and the injection of a mixture of lighthydrocarbon and steam is undertaken. As in the first step, it isdesirable that the mixture be injected at the maximum flow rate possibleconsistent with the pressure limitations of the formation. The injectionof the mixture of light hydrocarbon and steam is continued until theoverall production recovery begins to decrease or production has reachedan undesirably low productive level. Thereafter, the sequence ofinjection steps may be repeated. Thus, the invention may employ a seriesof injection cycles comprising the steps of injection of a mixture of anoxygen-containing gas and steam, followed by the injection of a mixtureof a light hydrocarbon and steam.

The light hydrocarbon that is commingled with the steam may be anysuitable solvent such as aliphatic hydrocarbons having from 3 to 10carbon atoms per molecule, cyclic aromatics, such as benzene or toluene,and naphthenic hydrocarbons. The hydrocarbon may also be naturalgasoline, naphtha, kerosene and hydrocarbon mixtures containing aromaticfractions. A preferred solvent is naphtha that is a cut of a refinerystream having a boiling range of about 85° F. to about 460° F.

The ratio of the light hydrocarbon to the steam should be in the rangeof about 0.03 bbl/bbl to about 0.33 bbl/bbl or about 3 volume % to 33volume % with the preferred range being about 0.05 bbl/bbl to 0.12bbl/bbl or 5 volume % to 12 volume %. It is preferred that thecommingled steam be saturated steam having a quality in the range ofabout 60% to about 100%.

It is postulated that the benefits realized from the disclosed sequencerelate to the fact that in the first step, using a mixture of anoxygen-containing gas and steam, the low-temperature oxidation thatoccurs results principally from the mechanism of cleavage of asphalticclusters with molecular degradation. The process may be considered as acontrolled oxidation process wherein the saturated steam partiallyquenches any incipient burning near the injection point, therebypreventing the temperature from rising to the point of carbonization ofthe bitumen. With the control of the temperature, the carbon reactionsare reduced and the unreacted oxygen is capable of penetrating into theformation so as to propagate the controlled oxidation reaction moreextensively throughout the formation.

It is further postulated that the use of the mixture of lighthydrocarbon and steam in the second step has the advantage not only of athermal and solvent action on the bitumen, but also that by vaporizationof the solvent a resulting beneficial volume increase occurs. By thecombination of the two steps optimized recovery is obtained that isbetter than the recovery from the use of either step alone.

The optimized recovery realized by the disclosed invention has beendemonstrated from the results and analyses of a series of laboratoryruns, which will be described in greater detail hereinafter, thatinvestigated the recovery of bitumen from tar sand employing both amixture of an oxygen-containing gas and steam and a mixture of a lighthydrocarbon and steam. These runs showed in all cases that during theearly stages of the runs the percent recovery showed the greatestchange. Further, the recovery efficiency in all runs rose to a maximumvalue and then declined after about one pore volume of steam had beeninjected. The results further demonstrated that the optimum recoveryefficiency that is obtained during this stage occurred when the mixtureof the oxygen-containing gas and steam was used as compared with amixture of a light hydrocarbon and steam. Thus, by the method of theinvention, the first step in the disclosed sequence employs theinjection of a mixture of an oxygen-containing gas and steam.

The results further demonstrated that after the recovery efficiency hadpeaked, the mixture of the light hydrocarbon and steam outperformed themixture of the oxygen-containing gas and steam as a recovery mechanism.Thus, again according to the invention, switchover from the first stepto the second step is made at the opportune time so that the benefits ofboth maximum recovery efficiency and maximum overall recovery arerealized in optimizing bitumen recovery.

In addition to the above recited advantages, it has been determined thatthe employment of a pressurization and drawdown cycle during operationimparts further beneficial results leading to enhanced recovery.Pressurization may be accomplished by maintaining the rate of productionat a value less than the rate of injection. The injection rate employedshould be such that the pressure in the formation is increased to avalue approaching the fracturing pressure or to a pressure at theproduction well of about 60-95% of the injection pressure. Restrictingthe production rate may be accomplished by, for example, choking backthe production wells. Once the desired pressure has been attained,drawdown is initiated by reducing the injection rate and increasing theproduction rate. The production rate may be increased by producing theproduction wells under essentially unrestricted conditions until thepressure of the formation declines to some desired lower level. Theinjection rate during drawdown may be as low as about 20% of the initialinjection rate and the pressure decline may be to about 33% of thepressure at the beginning of the drawdown cycle. Drawdown is maintainedso long as fluid is produced at a reasonable or economic rate. Once theproduction has declined below this value, a second pressurization anddrawdown cycle may be undertaken. The pressurization and drawdown cyclemay be employed during either or both of the injection steps and may berepeated during the injection sequence.

It is believed that the use of the pressurization and drawdown cycle isof benefit in that it accomplishes a periodic cleanout of thecommunication paths, thereby maintaining transmissibility, which must bemaintained if continued production of the formation is to be realized.

Returning now to the series of laboratory runs mentioned above, a seriesof runs was conducted using a tar sand from the McMurray formation inAlberta, Canada. For each run, approximately 170-190 pounds of tar sandwere packed in a cell approximately 15 inches long and 18 inches indiameter. The cell was equipped for operating at controlled temperaturesup to 420° F. and pressures up to 500 psia and contained suitablesimulated injection and production wells. The sand pack contained manythermocouples so that temperatures throughout the pack could be measuredand heat transfer rates could be calculated.

The general procedure employed involved the injection of steam tocondition the tar sand pack and to initiate production, after whichinjection of the fluid under study was undertaken. Injection rates,production rates, temperatures, and pressures were monitored during eachrun.

In laboratory Run No. 1 a mixture of an oxygen-containing gas (air) andsteam was injected at a pressure of about 300 psia and a temperature of417° F. corresponding to the saturation pressure of steam. The ratio ofthe air to the steam was about 0.7 SCF per pound of steam or 245 SCF perbbl of steam. The operating scheme employed an initial steam injectionperiod for about one-half hour. Thereafter, a mixture of air and steamwas injected for about 11/2 hours followed by a pressurization anddrawdown cycle period of about 12 hours. The pressurization and drawdowncycle consisted of 10 minutes of injection at a pressure of about 300psia followed by a drawdown of 30 minutes wherein the simulatedproduction well was produced until the pressure had decreased to aboutatmospheric pressure. Recovery was approximately 50% after 2 porevolumes of steam had been injected. The results showed that not only wasrecovery significantly improved by the use of a commingled air and steammixture as compared with the use of steam only, but also the use of thepressurization and drawdown cycle sharply increased the recovery rateand the conformance.

These results may be compared with those of Run 2 in which steam onlywas injected and in which, after 2 hours of steam injection, thepressurization and drawdown cycle period was employed for about 18hours. With the introduction of the pressurization and drawdown cycle,production increased sharply as had been seen in Run 1. But afterapproximately 2 pore volumes of steam had been injected, recovery wasonly 36%.

In Run 3 a mixture of a light hydrocarbon (Unifiner naphtha) and steamwas injected. The ratio of the naphtha to steam was about 8.9 vol. %.The Unifiner naphtha had a distillation range from an initial boilingpoint (I.B.P.) of about 86° F. to an end point (E.P.) of about 385° F.Initially steam was injected for approximately 15 minutes andthereafter, the mixture of naphtha and steam was injected forapproximately 40 minutes at the temperature corresponding to thetemperature of saturated steam at the pressure of the test cell, afterwhich a pressurization and drawdown cycle period was undertaken forapproximately 141/2 hours. Recovery was about 42.5% after 2 pore volumesof steam had been injected. The results showed that the recovery rateswere not so high at the beginning of the run as those with the mixtureof air and steam, but there was indication that the use of thepressurization and drawdown cycle sharply increased recovery rates.

In Run 4 the sequential procedure was used, injecting first a mixture ofair and steam followed by injecting a mixture of Unifiner naphtha andsteam. The operating scheme consisted of an initial steam injectionperiod for approximately one-half hour. Thereafter, the mixture of airand steam was injected in which the ratio of air to steam was about 0.67SCF/lb. steam or about 235 SCF/bbl. After about half an hour, apressurization and drawdown cycle period was undertaken in which air andsteam were injected for 10 minutes followed by drawdown for 30 minutes.After approximately 11 hours, injection of the mixture was terminatedand injection of the mixture of Unifiner naphtha and steam wasundertaken in which pressurization and drawdown cycles were againemployed. The results show that during the first step of injection ofthe mixture of air and steam the production rate or recovery efficiencywas very high at the start and gradually decreased as the runprogressed. The results also show that with the initiation of theinjection of the mixture of naphtha and steam the decline in recoveryrate was arrested and after about 5 hours of injection, the productionrate began to increase.

The results and analyses of these runs are illustrated in theaccompanying figures. In FIG. 1 the percent bitumen recovery versus thepore volume of steam injected is plotted for the above-described runs.The figure clearly shows the advantages in terms of recovery of using asthe injection fluid a mixture of air and steam (Run 1) or a mixture oflight hydrocarbon and steam (Run 3) over straight steam (Run 2). Forexample, with straight steam (Run 2) aproximately 25% recovery wasobtained after one pore volume of steam had been injected. In contrastto this, when a mixture of air and steam was used (Run 1) approximately42% recovery was obtained, and when a mixture of naphtha and steam wasused (Run 3) approximately 32% recovery was obtained after one porevolume of steam had been injected.

FIG. 1 also shows that for all cases the region of most significantchange in recovery occurred when about 1.0 to 1.1 pore volumes of steamhad been injected. Furthermore, the percent recovery shows the greatestchange for the air and steam run. Thereafter, recovery is less for theair and steam run as compared with the light hydrocarbon and steam run.

Using these results, the slopes of the curves were then plotted againstpore volumes of steam injected, as shown in FIG. 2. These slopes are therecovery efficiency expressed as pore volume bitumen to pore volumesteam. The results show that maximum recovery efficiency for both theair and steam mixture (Run 1) and the light hydrocarbon and steammixture (Run 3) occurs when somewhat less than one pore volume of steamhas been injected. The figure also shows that the use of a mixture ofair and steam results in optimum performance in terms of recoveryefficiency when compared with the mixture of light hydrocarbon andsteam. Further, the figure shows that for pore volumes greater than onepore volume of steam injected, the recovery efficiency for the mixtureof light hydrocarbon and steam is significantly higher than that for airand steam.

Thus, as disclosed by the instant invention, to optimize bitumenrecovery for a given pore volume of steam injected, the general sequenceemployed is to maximize the recovery efficiency by initiating injectionwith a mixture of air and steam until the recovery efficiency shows adecline, following which the injection of the mixture of air and steamis terminated and the injection of the mixture of light hydrocarbon andsteam is initiated. The optimized procedure is shown by the heavy dashedline in FIG. 2.

The results of a laboratory run using the procedure is shown in FIG. 3wherein a mixture of air and steam was injected followed by theinjection of a mixture of light hydrocarbon (Unifiner naphtha) andsteam, and utilizing pressurization and drawdown cycles. Switchover wasmade after 2.3 pore volumes of steam had been injected. The resultsindicate the improved recovery obtained by employing the sequentialoptimized procedure of the disclosed invention. The observed improvementin recovery is clearly shown in that the recovery continues to increaseafter switchover, whereas the recovery utilizing the mixture of air andsteam has leveled off.

In summary, in accordance with the invention improved recovery of heavyoil or bitumen is accomplished by an optimized procedure in which amixture of an oxygen-containing gas and steam is injected at atemperature corresponding to the temperature of saturated steam at thepressure of the formation until maximum recovery efficiency has beenrealized, followed by the injection of a light hydrocarbon and steam.Pressurization and drawdown cycles may be utilized in each step.

We claim:
 1. A method for the recovery of hydrocarbons from asubterranean hydrocarbon-bearing formation traversed by at least oneinjection well and one production well and having fluid communicationtherebetween, comprising the steps of:(a) injecting via said injectionwell a first mixture comprising an oxygen-containing gas and steam,until the maximum recovery efficiency has been attained and starts todecline and simultaneously producing said formation hydrocarbons viasaid production well, (b) terminating injection of said first mixtureand undertaking injection of a second mixture comprising a lighthydrocarbon and steam and continuing to produce said formationhydrocarbons via said production well, wherein a pressurization anddrawdown cycle is employed during at least one of said steps (a) and(b).
 2. The method of claim 1 wherein steam is injected into saidinjection and/or said production wells to condition said formation,prior to the injection of said first mixture.
 3. The method of claim 1wherein said injected steam has a quality of less than 100%.
 4. Themethod of claim 1 wherein said first mixture is injected at atemperature corresponding to the temperature of saturated steam at thepressure of said formation.
 5. The method of claim 1 wherein the ratioof the free oxygen in said oxygen-containing gas to steam in said firstmixture is in the range of about 30 to 130 SCF per barrel of steam. 6.The method of claim 1 wherein said formation is first repressured to apressure corresponding to a temperature for saturated steam in the rangeof 250°-500° F.
 7. The method of claim 1 wherein said mixture ofoxygen-containing gas and steam is injected until about 1 to 1.1 porevolume of steam at reservoir conditions has been injected.
 8. The methodof claim 1 wherein said oxygen-containing gas is air, enriched oxygen,or substantially pure oxygen.
 9. The method of claim 1 wherein the ratioof light hydrocarbon to steam in said second mixture is in the range ofabout 3.0 vol. % to 33.0 vol. %.
 10. The method of claim 1 wherein saidlight hydrocarbon comprises aliphatic hydrocarbons having from 3 to 10carbon atoms per molecule, cyclic aromatics, naphthenic hydrocarbons andmixtures thereof.
 11. The method of claim 1 wherein said lighthydrocarbon is natural gasoline, naphtha, kerosene, and mixturesthereof.
 12. The method of claim 1 wherein said light hydrocarbon is acut of a refinery stream having a boiling range of about 85° F. (I.B.P.)to about 460° F. (E.P.).
 13. The method of claim 1 wherein steps (a) and(b) are repeated when production has reached an undesirably low level.14. The method of claim 1 wherein said pressurization and drawdown cyclecomprises:(a) pressurization wherein the rate of production is less thanthe rate of injection, (b) drawdown wherein the rate of production isgreater than the rate of injection.
 15. The method of claim 1 whereinsaid pressurization and said drawdown cycle comprises:(a) pressurizationwherein said injection mixture is injected at a rate until the pressureat said production well is increased to about 60% to about 95% of theinjection pressure and said production well is produced at restrictedconditions, (b) drawdown wherein said injection mixture is injected at arate of about 20% to about 33% of the initial injection rate and saidproduction well is produced at essentially unrestricted conditions. 16.The method of claim 1 wherein said pressurization and drawdown cycle isrepeated.
 17. A method for the recovery of bitumen from a tar sandformation traversed by at least one injection well and at least oneproduction well comprising the steps of:(a) injecting via said injectionwell a first mixture to an oxygen-containing gas and steam said steamhaving a quality less than 100% and said mixture being injected at atemperature corresponding to the temperature for saturated steam at thepressure of said formation, while simultaneously producing saidformation bitumen via said production well, (b) terminating injection ofsaid first mixture after the maximum recovery efficiency has beenattained and injecting a second mixture of a light hydrocarbon and steamwhile continuing to produce said formation bitumen via said productionwell, wherein a pressurization and drawdown cycle is employed during atleast one of said steps (a) and (b).
 18. The method of claim 17 whereinsteps (a) and (b) are repeated when production has reached anundesirably low level.
 19. The method of claim 17 wherein steam isinjected into said injection and/or said production wells to conditionsaid formation prior to the injection of said first mixture.
 20. Themethod of claim 17 wherein the ratio of free oxygen in saidoxygen-containing gas to steam in said first mixture is in the range ofabout 30 to 130 SCF/bbl of steam.
 21. The method of claim 17 whereinsaid formation is first repressured to a pressure corresponding to atemperature for saturated steam in the range of 250° to 500° F.
 22. Themethod of claim 17 wherein said mixture of oxygen-containing gas andsteam is injected until about 1 to 1.1 pore volumes of steam atreservoir conditions has been injected.
 23. The method of claim 17wherein said oxygen-containing gas is air, enriched oxygen orsubstantially pure oxygen.
 24. The method of claim 17 wherein the ratioof light hydrocarbon to steam in said second mixture is in the range ofabout 3.0 vol. % to 33.0 vol. %.
 25. The method of claim 17 wherein saidlight hydrocarbon comprises aliphatic hydrocarbons having from 3 to 10carbon atoms per molecule, cyclic aromatics, naphthenic hydrocarbons,and mixtures thereof.
 26. The method of claim 17 wherein said lighthydrocarbon is natural gasoline, naphtha, kerosene and mixtures thereof.27. The method of claim 17 wherein said pressurization and drawdowncycle comprises:(a) pressurization wherein the rate of production isless than the rate of injection, (b) drawdown wherein the rate ofproduction is greater than the rate of injection.
 28. The method ofclaim 17 wherein said pressurization and drawdown cycle is repeated.